Note: Descriptions are shown in the official language in which they were submitted.
WASTE HEAT RECOVERY FROM DEPLETED RESERVOIR
FIELD
[0001] The present disclosure relates generally to methods of
producing heat from a
depleted reservoir.
BACKGROUND
[0002] A variety of processes are used to recover viscous
hydrocarbons, such as
heavy oils and bitumen, from reservoirs such as oil sands deposits. Extensive
deposits of
viscous hydrocarbons exist around the world, including large deposits in the
Northern Alberta
oil sands that are not susceptible to standard oil well production
technologies. One problem
associated with producing hydrocarbons from such deposits is that the
hydrocarbons are too
viscous to flow at commercially relevant rates at the temperatures and
pressures present in
the reservoir.
[0003] In some cases, such deposits are mined using open-pit mining
techniques to
extract hydrocarbon-bearing material for later processing to extract the
hydrocarbons.
Alternatively, thermal techniques may be used to heat the hydrocarbon
reservoir to mobilize
the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
[0004] One thermal method of recovering viscous hydrocarbons using
two vertically
spaced horizontal wells is known as steam-assisted gravity drainage (SAGD).
Various
embodiments of the SAGD process are described in Canadian Patent No. 1,304,287
and
corresponding U.S. Patent No. 4,344,485. In the SAGD process, steam is pumped
through
an upper, horizontal, injection well into a viscous hydrocarbon reservoir
while mobilized
hydrocarbons are produced from a lower, parallel, horizontal, production well
that is vertically
spaced and near the injection well. The injection and production wells are
located close to
the bottom of the hydrocarbon deposit to collect the hydrocarbons that flow
toward the
bottom.
[0005] The SAGD process is believed to work as follows. The injected
steam initially
mobilizes the hydrocarbons to create a steam chamber in the reservoir around
and above
the horizontal injection well. The term "steam chamber" is utilized to refer
to the volume of
the reservoir that is saturated with injected steam and from which mobilized
oil has at least
partially drained. As the steam chamber expands upwardly and laterally from
the injection
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well, viscous hydrocarbons in the reservoir are heated and mobilized, in
particular, at the
margins of the steam chamber where the steam condenses and heats the viscous
hydrocarbons by thermal conduction. The mobilized hydrocarbons and aqueous
condensate
drain, under the effects of gravity, toward the bottom of the steam chamber,
where the
production well is located. The mobilized hydrocarbons are collected and
produced from the
production well. The rate of steam injection and the rate of hydrocarbon
production may be
modulated to control the growth of the steam chamber and ensure that the
production well
remains located at the bottom of the steam chamber in an appropriate position
to collect
mobilized hydrocarbons.
[0006] In situ Combustion (ISC) is another thermal method which may be
utilized to
recover hydrocarbons from underground hydrocarbon reservoirs. ISC includes the
injection
of an oxidizing gas into the porous rock of a hydrocarbon-containing reservoir
to ignite and
support combustion of the hydrocarbons around the wellbore. ISC may be
initiated using an
artificial igniter such as a down hole heater or by pre-conditioning the
formation around the
wellbores and promoting spontaneous ignition. The ISC process, also known as
fire flooding
or fireflood, is sustained and the ISC fire front moves due to the continuous
injection of the
oxidizing gas. The heat generated by burning the heavy hydrocarbons in place
produces
hydrocarbon cracking, vaporization of light hydrocarbons and reservoir water
in addition to
the deposition of heavier hydrocarbons known as coke. As the fire moves, the
burning front
pushes a mixture of hot combustion gases, steam, and hot water, which in turn
reduces oil
viscosity and the oil moves toward the production well. Additionally, the
light hydrocarbons
and the steam move ahead of the burning front, condensing into liquids,
facilitating miscible
displacement and hot waterflooding, which contribute to the recovery of
hydrocarbons.
[0007] Canadian Patent 2,096,034 to Kisman et al. and US Patent
5,211,230 to
Ostapovich et al. disclose a method of in situ combustion for the recovery of
hydrocarbons
from underground reservoirs, sometimes referred to as Combustion Split
production
Horizontal well Process (COSH) or Combustion Overhead Gravity Drainage (COGD).
The
disclosed processes include gravity drainage to a basal horizontal well in a
combustion
process. A horizontal production well is located in the lower portion of the
reservoir. A vertical
injection and one or more vertical vent wells are provided in the upper
portion of the
reservoir. Oxygen-enriched gas is injected down the injector well and ignited
in the upper
portion of the reservoir to create a combustion zone that reduces viscosity of
oil in the
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reservoir as the combustion zone advances downwardly toward the horizontal
production
well. The reduced-viscosity oil drains into the horizontal production well
under the force of
gravity.
[0008] Canadian Patent 2,678,347 to Bailey discloses a pre-ignition
heat cycle
(PIHC) using cyclic steam injection and steam flood methods that improve the
recovery of
viscous hydrocarbons from a subterranean reservoir using an overhead in situ
combustion
process, referred to as combustion overhead gravity drainage (COGD). Bailey
discloses a
method where the reservoir well network includes one or more injection wells
and one or
more vent wells located in the top portion of the reservoir, and where the
horizontal drain is
located in the bottom portion of the reservoir.
[0009] The use of ISC as a follow up process to SAGD is disclosed in
Canadian
Patent 2,594,414 to Chhina et al. The disclosed hydrocarbon recovery processes
may be
utilized in hydrocarbon reservoirs. Chhina discloses a process where a former
steam
injection well, used during the preceding SAGD recovery process, is used as an
oxidizing
gas injection well and where another former steam injection well, adjacent to
the oxidizing
gas injection well, is converted into a combustion gas production well. This
results in the
horizontal hydrocarbon production well being located below the horizontal
oxidizing gas
injection well and at least one combustion gas production well being spaced
from the
injection well by a distance that is greater than the spacing between
hydrocarbon production
well and the oxidizing gas injection well. Since the process disclosed by
Chhina uses at least
two wells pairs, ISC is initiated after the production well is sufficiently
depleted of
hydrocarbons to establish communication between the two well pairs.
[0010] At the end of thermal based hydrocarbon recovery processes
there is residual
energy stored in the bitumen-depleted reservoir. In the case of steam-based
recovery
processes, this energy is the result of steam injection in the reservoir
during the life time of
the process. In the case of combustion-based recovery processes, this energy
is the result of
the heat of the combustion used to produce the hydrocarbons. It is desirable
to recover
thermal energy from hydrocarbon reservoir that has a hot bitumen-depleted
zone.
SUMMARY
[0011] In a first aspect, the present disclosure provides a method of
producing
heated water from a hydrocarbon reservoir having a hot bitumen-depleted zone.
The method
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includes injecting water into at least a portion of the hot bitumen-depleted
zone to heat the
water; and producing the heated water from a heated water production well.
[0012] The method may also include generating the hot bitumen-
depleted zone using
steam-assisted gravity drainage, in situ combustion, steam flooding, cyclic
steam stimulation,
a solvent aided thermal recovery process, electric heating, electromagnetic
heating, or any
combination thereof.
[0013] Injecting the water into at least a portion of the hot bitumen-
depleted zone
may heat the water sufficiently to generate steam in situ. The heated water
production well
may be located above at least a portion of the hot bitumen-depleted zone, and
the water may
be injected into the portion of the hot-bitumen depleted zone below the heated
water
production well.
[0014] Injecting the water into at least a portion of the hot bitumen-
depleted zone
may heat the water sufficiently to generate hot liquid water in situ. The
heated water
production well may be located below at least a portion of the hot bitumen-
depleted zone,
and the water may be injected into the portion of the hot-bitumen depleted
zone above the
heated water production well.
[0015] Injecting the water into at least a portion of the hot bitumen-
depleted zone
may heat the water sufficiently to generate both steam and hot liquid water in
situ. Heated
water may be produced from a first and a second heated water production well,
where the
first heated water production well is located above at least a portion of the
hot bitumen-
depleted zone; and the second heated water production well is located below at
least a
portion of the hot bitumen-depleted zone. The water may be injected into a
portion of the hot-
bitumen depleted zone below the first heated water production well and above
the heated
water production well. In such a situation, the first heated water production
well may produce
heated water from the generated steam, and the second heated water production
well may
produce heated water from the generated hot liquid water.
[0016] Other aspects and features of the present disclosure will
become apparent to
those ordinarily skilled in the art upon review of the following description
of specific
embodiments in conjunction with the accompanying figures.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0017] Embodiments of the present disclosure will now be described,
by way of
example only, with reference to the attached Figures.
[0018] Fig. 1 is an illustration of a first simulated reservoir.
[0019] Fig. 2 is an illustration of the temperature profile of the first
simulated reservoir
after 4 years of SAGD.
[0020] Fig. 3 is an illustration of the temperature profile of the
first simulated reservoir
after 1 year of injection of methane.
[0021] Fig. 4 is an illustration of the temperature profile of the
first simulated reservoir
after 2.28 years of injection of water.
[0022] Fig. 5 is a graph showing the cumulative energy injected and
produced for the
first simulated reservoir.
[0023] Fig. 6 is a graph showing the energy distribution at different
stages of the
process for the first simulated reservoir.
[0024] Fig. 7 is an illustration of a second simulated reservoir.
[0025] Fig. 8 is an illustration of the temperature profile of the
second simulated
reservoir after 4 years of SAGD.
[0026] Fig. 9 is an illustration of the temperature profile of the
second simulated
reservoir after 1 year of injection of methane.
[0027] Fig. 10 is an illustration of the temperature profile of the second
simulated
reservoir after 3.31 years of injection of water.
[0028] Fig. 11 is a graph showing the cumulative energy injected and
produced for
the second simulated reservoir.
[0029] Fig. 12 is a graph showing the energy distribution at
different stages of the
process for the second simulated reservoir.
[0030] Fig. 13 is an illustration of a third simulated reservoir.
[0031] Fig. 14 is an illustration of the temperature profile of the
third simulated
reservoir after 4 years of SAGD.
[0032] Fig. 15 is an illustration of the temperature profile of the
third simulated
reservoir after 1 year of injection of methane.
[0033] Fig. 16 is an illustration of the temperature profile of the
third simulated
reservoir after 5.82 years of injection of water.
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Date Recue/Date Received 2021-09-02
[0034] Fig. 17 is a graph showing the cumulative energy injected and
produced for
the third simulated reservoir.
[0035] Fig. 18 is a graph showing the energy distribution at
different stages of the
process for the third simulated reservoir.
[0036] Fig. 19 is an illustration of a fourth simulated reservoir.
[0037] Fig. 20 is an illustration of the temperature profile of the
fourth simulated
reservoir after 3.6 years of SAGD.
[0038] Fig. 21 is an illustration of the temperature profile of the
fourth simulated
reservoir after 2 year of injection of butane.
[0039] Fig. 22 is an illustration of the temperature profile of the fourth
simulated
reservoir after 1.2 years of injection of water.
[0040] Fig. 23 is a graph showing the cumulative energy injected and
produced for
the fourth simulated reservoir.
[0041] Fig. 24 is an illustration of a fifth simulated reservoir.
[0042] Fig. 25 is an illustration of the temperature profile of the fifth
simulated
reservoir after 3.6 years of SAGD.
[0043] Fig. 26 is an illustration of the temperature profile of the
fifth simulated
reservoir after 2 year of injection of butane.
[0044] Fig. 27 is an illustration of the temperature profile of the
fifth simulated
reservoir after 3.8 years of injection of water.
[0045] Fig. 28 is a graph showing the cumulative energy injected and
produced for
the fifth simulated reservoir.
[0046] Fig. 29 is a graph showing the energy distribution at
different stages of the
process for the fifth simulated reservoir.
[0047] Fig. 30 is an illustration of a sixth simulated reservoir.
[0048] Fig. 31 is an illustration of the temperature profile of the
sixth simulated
reservoir after 5 years of SAGD and 4.5 years of in situ combustion.
[0049] Fig. 32 is an illustration of the temperature profile of the
sixth simulated
reservoir after 0.3 years of injection of water.
[0050] Fig. 33 is an illustration of the temperature profile of the sixth
simulated
reservoir after 0.9 years of injection of water.
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[0051] Fig. 34 is an illustration of the temperature profile of the
sixth simulated
reservoir after 1.5 years of injection of water.
[0052] Fig. 35 is a graph showing the cumulative energy injected and
produced for
the sixth simulated reservoir.
[0053] Fig. 36 is a graph showing the energy distribution at different
stages of the
process for the sixth simulated reservoir.
DETAILED DESCRIPTION
[0054] Generally, the present disclosure provides a method of
producing heated
water from a hydrocarbon reservoir having a hot bitumen-depleted zone. The
method
includes: injecting water into at least a portion of the hot bitumen-depleted
zone to heat the
water; and producing the heated water from a heated water production well. The
water may
be injected using an injection well.
[0055] The method may also include generating the hot bitumen-
depleted zone using
steam-assisted gravity drainage, in situ combustion, steam flooding, cyclic
steam stimulation,
a solvent aided thermal recovery process, electric heating, electromagnetic
heating, or any
combination thereof.
[0056] Injecting the water into at least a portion of the hot bitumen-
depleted zone
may heat the water sufficiently to generate steam in situ. The heated water
production well
may be located above at least a portion of the hot bitumen-depleted zone, and
the water may
be injected into the portion of the hot-bitumen depleted zone below the heated
water
production well.
[0057] Injecting the water into at least a portion of the hot bitumen-
depleted zone
may heat the water sufficiently to generate hot liquid water in situ. The
heated water
production well may be located below at least a portion of the hot bitumen-
depleted zone,
and the water may be injected into the portion of the hot-bitumen depleted
zone above the
heated water production well.
[0058] Injecting the water into at least a portion of the hot bitumen-
depleted zone
may heat the water sufficiently to generate both steam and hot liquid water in
situ. Heated
water may be produced from a first and a second heated water production well,
where the
first heated water production well is located above at least a portion of the
hot bitumen-
depleted zone; and the second heated water production well is located below at
least a
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portion of the hot bitumen-depleted zone. The water may be injected into a
portion of the hot-
bitumen depleted zone below the first heated water production well and above
the heated
water production well. In such a situation, the first heated water production
well may produce
heated water from the generated steam, and the second heated water production
well may
produce heated water from the generated hot liquid water.
[0059] It is not necessary that the bitumen-depleted zone be
completely depleted of
bitumen. Accordingly, in the context of the present application, a bitumen-
depleted zone
would be understood to refer to a zone in the hydrocarbon reservoir where it
is not
commercially viable to continue to extract bitumen from the hydrocarbon
reservoir, even
though residual bitumen may be present in the hydrocarbon reservoir. In some
hydrocarbon
reservoirs, it may no longer be commercially viable to extract bitumen once
the average
residual oil saturation level is less than 40%. In other hydrocarbon
reservoirs, it may no
longer be commercially viable to extract bitumen once the average residual oil
saturation
level is less than 30%. In yet other hydrocarbon reservoirs, it may no longer
be commercially
viable to extract bitumen once the average residual oil saturation level is
less than 20%. In
some especially productive hydrocarbon reservoirs, it may no longer be
commercially viable
to extract bitumen once the average residual oil saturation level is less than
10-15%.
[0060] A hot bitumen-depleted zone is to be understood to refer to a
bitumen-
depleted zone whose temperature is elevated by heat used in a thermal bitumen-
recovery
process that generates the bitumen-depleted zone. In particular examples, the
hot bitumen-
depleted zone is generated by steam-assisted gravity drainage, in situ
combustion, a solvent
aided thermal recovery process, electric heating, electromagnetic heating, or
any
combination thereof.
[0061] In some examples, the hot bitumen-depleted zone has an average
temperature of at least 10 C. For example, the hot bitumen-depleted zone may
have an
average temperature of between 20 and 300 C when the hot bitumen-depleted
zone is
generated by steam-assisted gravity drainage. In another example, the hot
bitumen-depleted
zone may have an average temperature of between 20 and 600 C when the hot
bitumen-
depleted zone is generated by in situ combustion. In yet another example, the
hot bitumen-
depleted zone may have an average temperature of between 20 and 400 C when
the hot
bitumen-depleted zone is generated by electromagnetic heating.
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[0062] Regardless of the thermal bitumen recovery method used to
generate the hot
bitumen-depleted zone, some hot bitumen-depleted zones may have conditions
that
generate steam from the water, while other hot bitumen-depleted zones may have
conditions
that generate hot liquid water. A hot bitumen-depleted zone may, at a specific
point in time,
have conditions that generate steam, and, at a later point in time, may have
conditions that
generate hot liquid water.
[0063] When generating steam in the hot bitumen-depleted zone, it is
desirable to
place the heated water production well above at least a portion of the hot
bitumen-depleted
zone. In such a manner, the water that is injected into the portion of the hot-
bitumen depleted
zone below the heated water production well may be turned into steam, which
rises up to the
heated water production well.
[0064] It is not necessary for the heated water production well to be
placed above at
least a portion of the hot bitumen-depleted zone. Steam may be driven from an
upper portion
of the hot bitumen-depleted zone downwards to a heated water production well
placed below
at least a portion of the hot bitumen-depleted zone. Alternatively, steam may
be driven
substantially across a portion of the hot bitumen-depleted zone to a heated
water production
well that is at substantially the same level as the liquid water injection
well. The steam may
be produced from the heated water production well as steam or as hot liquid
water.
[0065] When generating hot liquid water in the hot bitumen-depleted
zone, it is
desirable to place the heated water production well below at least a portion
of the hot
bitumen-depleted zone. In such a manner, the water that is injected into the
portion of the
hot-bitumen depleted zone above the heated water production well may be turned
into hot
liquid water, which descends due to gravity to the heated water production
well.
[0066] It is not necessary for the heated water production well to be
placed below at
least a portion of the hot bitumen-depleted zone. Liquid water may be driven
from a lower
portion of the hot bitumen-depleted zone upwards to a heated water production
well placed
above at least a portion of the hot bitumen-depleted zone. Alternatively,
liquid water may be
driven substantially across a portion of the hot bitumen-depleted zone to a
heated water
production well that is at substantially the same level as the liquid water
injection well.
[0067] In some examples, injecting the liquid water in at least a portion
of the hot
bitumen-depleted zone may heat the water sufficiently to generate both steam
and hot liquid
water in situ. When generating both steam and hot liquid water, the method may
include
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Date Recue/Date Received 2021-09-02
producing heated water from a first and a second heated water production well.
In such
situations, the first heated water production well is located above at least a
portion of the hot
bitumen-depleted zone; and the second heated water production well is located
below at
least a portion of the hot bitumen-depleted zone. The water is injected into a
portion of the
hot-bitumen depleted zone below the first heated water production well and
above the
heated water production well, and the first heated water production well
produces heated
water from the generated steam, and the second heated water production well
produces
water from the generated hot liquid water.
[0068] In the context of the presently disclosure, when referring to
'injecting water',
the term "water" should be understood to refer to a generally aqueous solution
that is injected
into at least a portion of the hot bitumen-depleted zone. The generally
aqueous solution may
include salts, non-aqueous solvents that are soluble in water, or both. The
generally aqueous
solution may be mixed with one or more non-aqueous solvents that are not
soluble in water.
The expression "injecting water" should be understood to also include
injecting this mixture
into at least a portion of the hot bitumen-depleted zone.
[0069] The expression "heated water" should be understood to mean
water that is at
a temperature higher than the temperature of the injected water. Heated water
may be liquid
water, or steam. The steam may be saturated steam (or "wet steam"), or
superheated steam
(or "dry steam"). Saturated steam could be considered to be a mixture of
liquid water and
water vapor.
[0070] Since both temperature and pressure affect whether the heated
water is a hot
liquid water or steam, water that is injected into a hot bitumen-depleted zone
as liquid water
may be produced at the heated water production well as steam. Accordingly, it
is the
conditions in the hot bitumen-depleted zone that would determine whether steam
or hot liquid
water is being driven through the portion of the hot-bitumen depleted zone. In
the context of
the present disclosure, it should be understood that reservoir conditions may
promote the co-
existence of both steam and liquid water. It should be understood that the
term "steam"
includes: water vapor in a vapor-liquid equilibrium (also referred to as
"saturated steam" or
"wet steam"), and a water vapor that is at a temperature higher than its
boiling point for the
pressure, which occurs when all the liquid water has evaporated or has been
removed from
the system (also referred to as "superheated steam" or "dry steam").
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[0071] Hot bitumen-depleted zones that have conditions that generate
steam in the
hot bitumen-depleted zone may, after thermal energy is removed from the hot
bitumen-
depleted zone, have conditions that generate hot liquid water in the hot
bitumen-depleted
zone. The method may use a first heated water production well that is located
above at least
a portion of the hot bitumen-depleted zone when the hot bitumen-depleted zone
has
conditions that generate steam, and a second heated water production well that
is located
below at least a portion of the hot bitumen-depleted zone when the hot bitumen-
depleted
zone has conditions that generate hot liquid water.
Example 1
[0072] A simulation of a process according to the present disclosure
reservoir was
performed.
[0073] An illustration of the simulated reservoir is shown in Fig. 1,
including the water
injection wells 102. The SAGD pattern is a two-dimensional model whose
dimensions are
50m x 2m x 24m. These dimensions correspond to a horizontal well pair that is
2m long with
a 24m pay thickness and a 100m lateral well spacing. However, only half of the
reservoir was
simulated due to symmetry, with the SAGD well pair on the left and the water
injection well
102 on the right of the model. Additionally, only 2 m of well pair length were
simulated as the
model is 2-dimensional.
[0074] 1500 grid blocks were used as this number was adequate enough to
build an
accurate model. The dimensions for each of these blocks are lm x 2m x 0.8m in
the X, Y,
and Z directions respectively. The SAGD injection well was placed 4 m above
the SAGD
producing well which is located at the bottom of the reservoir.
[0075] Table 1 shows the reservoir and fluid parameters used in the
simulation.
Average Gross Pay (m) 24
Porosity (%) 0.33
Bitumen Saturation (%) 0.8
Water Saturation (%) 0.2
Vertical Permeability (mD) 4000
Kv/Kh 0.8
Viscosity (mPa.$) at 20 C 2,670,000
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Bitumen Density (kg/m3) at 20 C 1014.8
Reservoir Temperature ( C) 11
Reservoir Pressure (kPa) 2200
Table 1
[0076] Table 2 shows the injection rates used in the simulation,
where the *'ed
entries assume a 700 m length well pair.
Steam injection (CWE) t/d 0.65 455*
Methane injection t/d 0.0057 4*
Cold water injection t/d 1.5 1050*
Table 2
[0077] In the simulation, bitumen is produced via steam-assisted gravity
drainage for
a period of 4 years. After the 4 years of SAGD operation, steam injection is
ended and the
hydrocarbon recovery factor is 65.2%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 2. The temperature ranges from 228 C to 11 C
with color
indicating the temperature in each simulated cell. Red represents hotter
temperatures and
blue represents cooler temperatures.
[0078] At the end of 4 years, methane is injected for a period of 1
year in order to
continue to produce hydrocarbon without injecting additional heat into the
reservoir. This may
be referred to as "methane blowdown". After the 1 year of injection of
methane, the
hydrocarbon recovery factor is 71.4%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 3.
[0079] After injection of methane, water is injected for a period of
2.28 years. The
water is injected into a portion of the hot bitumen-depleted zone that is
above the heated
water production well and heated water is produced from what was previously
the SAGD
producing well. After the 2.28 years of injection of water, the hydrocarbon
recovery factor is
72.9%. The temperature profile of the simulated hot bitumen depleted zone is
shown in Fig.
4.
[0080] The cumulative energy injected and produced for the simulation
is illustrated
in Fig. 5. The energy distribution at different stages of the process is
illustrated in Fig. 6. The
energy recovered between blow-down and the end of water injection (4.53e8 kJ)
represents
57.6 % of the energy accumulated at blow-down (7.859e8 kJ).
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Example 2
[0081] A simulation of a process according to the present disclosure
reservoir was
performed.
[0082] An illustration of the simulated reservoir is shown in Fig. 7,
including the water
injection wells 702. The reservoir initial parameters were the same as in
Example 1. Only half
of the reservoir was simulated due to symmetry, with the water injection well
located on the
top right and two SAGD well pairs.
[0083] Table 3 shows the injection rates used in the simulation,
where the *'ed
entries assume a 700 m length well pair.
Steam injection (CWE) t/d 1.95 1365*
Methane injection t/d 0.0171 11.97*
Cold water injection t/d 4 2800*
Table 3
[0084] In the simulation, bitumen is produced via steam-assisted
gravity drainage for
a period of 4 years. After the 4 years of SAGD operation, steam injection is
ended and the
hydrocarbon recovery factor is 64.2%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 8. The temperature ranges from 233 C to 11 C
with color
indicating the temperature in each simulated cell. Red represents hotter
temperatures and
blue represents cooler temperatures.
[0085] At the end of 4 years, methane is injected for a period of 1
year in order to
continue to produce hydrocarbon without injecting additional heat into the
reservoir. This may
be referred to as "methane blowdown". After the 1 year of injection of
methane, the
hydrocarbon recovery factor is 72.9%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 9.
[0086] After injection of methane, water is injected for a period of
3.31 years. The
water is injected into a portion of the hot bitumen-depleted zone that is
above the heated
water production well and heated water is produced from what was previously
the SAGD
producing well. Water is injected into the well located at the upper corners
of the reservoir.
When the temperature of the produced water in the outer producing wells
decreased to 90
C, these wells were closed. In this simulation, the first SAGD well pair is
shut-in at 6.16
years (i.e. after 1.16 years of water injection). Water continues to be
injected and is produced
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Date Recue/Date Received 2021-09-02
through the middle producer until T = 90 C. After the 3.31 years of injection
of water, the
hydrocarbon recovery factor is 73.7%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 10.
[0087] The cumulative energy injected and produced for the simulation
is illustrated
in Fig. 11. The energy distribution at different stages of the process is
illustrated in Fig. 12.
The energy recovered between blow-down and the end of water injection (1.88e9
kJ)
represents 77.36% of the energy accumulated at blow-down (2.43e9 kJ).
Example 3
[0088] A simulation of a process according to the present disclosure
reservoir was
performed.
[0089] An illustration of the simulated reservoir is shown in Fig.
13. The full reservoir
was simulated due to asymmetry, with the water injection well 1302 located on
the top right
and the heated water production well 1304 located on the top left. The SAGD
pattern is a
two-dimensional model whose dimensions are 300m x 2m x 24m. These dimensions
correspond to a horizontal well pair that is 2m long with a 24m pay thickness
and a 100m
lateral well spacing. 9000 grid blocks were used as this number was adequate
enough to
build an accurate model. The dimensions for each of these blocks are 1m x 1m x
0.8m in the
X, Y, and Z directions respectively.
[0090] Table 4 shows the injection rates used in the simulation, where the
*'ed
entries assume a 700 m length well pair.
Steam injection (CWE) t/d 3.9 1365*
Methane injection t/d 0.0342 11.97*
Cold water injection t/d 3-5 1050-1750*
Table 4
[0091] In the simulation, bitumen is produced via steam-assisted
gravity drainage for
a period of 4 years. After the 4 years of SAGD operation, steam injection is
ended and the
hydrocarbon recovery factor is 64.6%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 14. The temperature ranges from 233 C to 11 C
with color
indicating the temperature in each simulated cell. Red represents hotter
temperatures and
blue represents cooler temperatures.
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Date Recue/Date Received 2021-09-02
[0092] At the end of 4 years, methane is injected for a period of 1
year in order to
continue to produce hydrocarbon without injecting additional heat into the
reservoir. This may
be referred to as "methane blowdown". After the 1 year of injection of
methane, the
hydrocarbon recovery factor is 73.4%. The temperature profile of the simulated
hot bitumen
depleted zone is shown in Fig. 15.
[0093] After injection of methane, water is injected into the water
injection well at the
top right, and produced from the heated water production well at the top left,
for a period of
5.82 years. After the 5.82 years of injection of water, the hydrocarbon
recovery factor is
73.44%. The temperature profile of the simulated hot bitumen depleted zone is
shown in Fig.
16.
[0094] The cumulative energy injected and produced for the simulation
is illustrated
in Fig. 17. The energy distribution at different stages of the process is
illustrated in Fig. 18.
The energy recovered between blow-down and the end of water injection (4.32e9
kJ)
represents 88.5% of the energy accumulated at blow-down (4.88e9 kJ).
Example 4
[0095] A simulation of a process according to the present disclosure
reservoir was
performed.
[0096] An illustration of the simulated reservoir is shown in Fig.
19. The SAGD
pattern is a two-dimensional model whose dimensions are 50m x 2m x 24m. These
dimensions correspond to a horizontal well pair that is 2m long with a 24m pay
thickness and
a 100m lateral well spacing. However, only half of the reservoir was simulated
due to
symmetry, with the SAGD well pair on the left and the water injection well
1902 on the right
of the model. Additionally, only 2 m of well pair length were simulated as the
model is 2-
dimensional.
[0097] 1500 grid blocks were used as this number was adequate enough
to build an
accurate model. The dimensions for each of these blocks are lm x 2m x 0.8m in
the X, Y,
and Z directions respectively. The SAGD injection well was placed 4 m above
the SAGD
producing well which is located at the bottom of the reservoir.
[0098] Table 5 shows the reservoir and fluid parameters used in the
simulation.
Average Gross Pay (m) 24
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Date Recue/Date Received 2021-09-02
Porosity (%) 0.33
Bitumen Saturation (%) 0.8
Water Saturation (%) 0.2
Vertical Permeability (mD) 4000
Kv/Kh 0.8
Viscosity (mPa.$) at 20 C 2,670,000
Bitumen Density (kg/m3) at 20 C 1014.8
Reservoir Temperature ( C) 11
Reservoir Pressure (kPa) 2200
Table 5
[0099] Table 6 shows the injection rates used in the simulation,
where the *'ed
entries assume a 700 m length well pair.
Steam injection (CWE) t/d 0.65 455*
Butane injection t/d 0.0057 4*
Cold water injection t/d 1.5 1050*
Table 6
[00100] In the simulation, bitumen is produced via steam-assisted gravity
drainage for
a period of 3.6 years. After the 3.6 years of SAGD operation, steam injection
is ended and
the hydrocarbon recovery factor is 60.7%. The temperature profile of the
simulated hot
bitumen depleted zone is shown in Fig. 20. The temperature ranges from 234 C
to 11 C
with color indicating the temperature in each simulated cell. Red represents
hotter
temperatures and blue represents cooler temperatures.
[00101] At the end of 3.6 years, butane is injected for a period of 2
years in order to
continue to produce hydrocarbon without injecting additional heat into the
reservoir. This may
be referred to as "butane blowdown". After the 2 year of injection of butane,
the hydrocarbon
recovery factor is 83.7%. The temperature profile of the simulated hot bitumen
depleted zone
is shown in Fig. 21.
[00102] After injection of methane, water is injected for a period of
1.2 years. The
water is injected into a portion of the hot bitumen-depleted zone that is
above the heated
water production well and heated water is produced from what was previously
the SAGD
producing well. After the 1.2 years of injection of water, the hydrocarbon
recovery factor is
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Date Recue/Date Received 2021-09-02
83.7%. The temperature profile of the simulated hot bitumen depleted zone is
shown in Fig.
22.
[00103] The cumulative energy injected and produced for the simulation
is illustrated
in Fig. 23. The energy recovered between blow-down and the end of water
injection (2.92e8
kJ) represents 43.5 % of the energy accumulated at blow-down (7.71e8 kJ).
Example 5
[00104] A simulation of a process according to the present disclosure
reservoir was
performed.
[00105] An illustration of the simulated reservoir is shown in Fig. 24. The
reservoir
initial parameters were the same as in Example 2, except that butane is
injected at a rate of
0.195 t/d (10% of the steam injection rate), which is higher than the rate of
methane injection
to account for the larger simulated reservoir. Only half of the reservoir was
simulated due to
symmetry, with the water injection well 2402 located on the top right and two
SAGD well
pairs.
[00106] In the simulation, bitumen is produced via steam-assisted
gravity drainage for
a period of 3.6 years. After the 3.6 years of SAGD operation, steam injection
is ended and
the hydrocarbon recovery factor is 60.2%. The temperature profile of the
simulated hot
bitumen depleted zone is shown in Fig. 25. The temperature ranges from 239 C
to 11 C
with color indicating the temperature in each simulated cell. Red represents
hotter
temperatures and blue represents cooler temperatures.
[00107] At the end of 3.6 years, butane is injected for a period of 2
years in order to
continue to produce hydrocarbon without injecting additional heat into the
reservoir. This may
be referred to as "butane blowdown". After the 2 year of injection of butane,
the hydrocarbon
recovery factor is 81.1%. The temperature profile of the simulated hot bitumen
depleted zone
is shown in Fig. 26.
[00108] After injection of butane, water is injected for a period of
3.8 years. The water
is injected into a portion of the hot bitumen-depleted zone that is above the
heated water
production well and heated water is produced from what was previously the SAGD
producing
well. Water is injected into the well located at the upper corners of the
reservoir. When the
temperature of the produced water in the outer producing wells decreased to 90
C, these
wells were closed. In this simulation, the first SAGD well pair is shut-in at
6.25 years (i.e.
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Date Recue/Date Received 2021-09-02
after 0.65 years of water injection). Water continues to be injected and is
produced through
the middle producer until T = 90 C. After the 3.8 years of injection of
water, the hydrocarbon
recovery factor is 81.1%. The temperature profile of the simulated hot bitumen
depleted zone
is shown in Fig. 27.
[00109] The cumulative energy injected and produced for the simulation is
illustrated
in Fig. 28. The energy distribution at different stages of the process is
illustrated in Fig. 29.
The energy recovered between blow-down and the end of water injection (1.59e9
kJ)
represents 79.5% of the energy accumulated at blow-down (2.00e9 kJ).
Example 6
[00110] A simulation of a process according to the present disclosure
reservoir was
performed.
[00111] An illustration of the simulated reservoir is shown in Fig.
30. The reservoir
initial parameters were the same as in Example 5. Only a third of the
reservoir was simulated
due to symmetry, with two oxidizing gas injector wells located on the top
corners and one
SAGD well pair located at the bottom center.
[00112] In the simulation, bitumen is produced via steam-assisted
gravity drainage for
a period of 5 years. After the 5 years of SAGD operation, steam injection is
ended and the
hydrocarbon recovery factor is 68.74%.
[00113] At the end of 5 years, oxidizing gas is injected for a period of
4.5 years in
order to produce hydrocarbons through in-situ combustion. After the 4.5 years
of in-situ
combustion, oxidizing gas injection is ended and the hydrocarbon recovery
factor is 75.43%.
[00114] After injection of oxidizing gas, water is injected for a
period of 1.5 years. The
water is injected into a portion of the hot bitumen-depleted zone through the
former SAGD
injection wells and heated water is produced from the former oxidizing gas
injection wells as
steam. After the 1.5 years of injection of water, the hydrocarbon recovery
factor is 75.43%.
[00115] The temperature profile of the simulated hot bitumen depleted
zone after 9.5
years, corresponding to the reservoir after in situ combustion but before
injection of water, is
shown in Fig. 31. The temperature ranges from 1245 C to 11 C with color
indicating the
temperature in each simulated cell. Red represents hotter temperatures and
blue represents
cooler temperatures.
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Date Recue/Date Received 2021-09-02
[00116] Temperature profiles of the simulated hot bitumen depleted
zone after 9.8 and
10.4 years, corresponding to the reservoir at two points during heat recovery,
are shown in
Figs. 32 and 33. In Fig. 32, the temperature ranges from 900 C to 11 C. In
Fig. 33, the
temperature ranges from 300 C to 11 C. The temperature profile of the
simulated hot
bitumen depleted zone after 11 years, corresponding to the reservoir at the
end of the heat
recovery phase, is shown in Fig. 34.
[00117] The cumulative energy injected and produced for the simulation
is illustrated
in Fig. 35. The energy distribution at different stages of the process is
illustrated in Fig. 36.
The energy recovered between in-situ combustion and the end of water injection
(1.353e9
kJ) represents 92.5% of the energy accumulated at the end of in situ
combustion (1.463e9
kJ).
[00118] In the preceding description, for purposes of explanation,
numerous details
are set forth in order to provide a thorough understanding of the examples.
However, it will
be apparent to one skilled in the art that these specific details are not
required. The above-
described examples are intended to be exemplary only. Alterations,
modifications and
variations can be effected to the particular examples by those of skill in the
art without
departing from the scope, which is defined solely by the claims appended
hereto.
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